Dan Watkiss, contributing editor
Although disparaged by budget watchdogs as a “piàƒ±ata of perks and pork,” the Domenici-Barton Energy Policy Act of 2005 contains two titles, Title XII, Electricity Modernization Act of 2005 and XIII, Energy Policy Tax Incentives, that promise to consolidate the power business, integrate transmission networks and their operation, reorder the hierarchy of power generation, and unleash far-reaching federal policing of deceptive and manipulative practices.
The 2005 Act repeals the Public Utility Holding Company Act of 1935 and replaces it with the Public Utility Holding Company Act of 2005 (PUHCA ’05) effective Feb. 8, 2006. The ’35 Act, more than any other law or regulation, produced the organization and structure of today’s power industry. It broke up the far-flung power trusts that flourished preceding the Great Depression and demanded that holding companies be confined thereafter to “a single integrated public-utility system, and to such other businesses as are reasonably incidental … to the operations of such integrated public-utility system.”
For 70 years, the integration requirement geographically confined investment and ownership of electric and natural gas utilities, while “incidental” confined the business lines into which utilities could diversify. PUHCA ’05 jettisons both limitations. The pending Duke/Cinergy and MidAmerican/PacifiCorp consolidations, which might both have been barred by the ’35 Act’s integration requirement, seem now to be harbingers of changes to come.
Elimination of the integration requirement will free existing utilities to acquire electric or gas distribution utilities in different regions of the country. Ending the incidental requirement opens the door for companies in other lines of business, or foreign companies, to invest in and own public-utility systems. Before PUHCA ’05, companies in the financial or industrial sectors, or extractive industries such as mining and oil and gas were largely prevented from investing in and owning public-utility systems. That now changes. The stable earnings and high dividends of franchised public utilities will induce investments from these other business sectors, provided state regulators are obliging. It was not PUHCA but local regulatory and public opposition to excessively leveraged capital structures and the perception of insufficient ratepayer benefits that killed the Texas Pacific Group’s bid for Portland General Electric and Kohlberg Kravis Roberts’ proposed leveraged buyout of the holding company of Tucson Electric Power.
PUHCA ’05 supplants the geographic and business-line restrictions of the ’35 Act with provisions designed to make the federal and state regulation of future public utility holding companies more transparent and effective. Books and records of future public utility holding companies and their affiliates will be available to the Federal Energy Regulatory Commission (FERC) and state regulatory bodies, and FERC will have expanded authority to review mergers and acquisitions, including those involving power generation plants, for consistency with the public interest.
Existing public utility holding companies (of which there are currently 29 registered companies) will continue operating under existing Securities and Exchange Commission (SEC) orders until the effective date. Notably, until the effective date, section 1081 of the Internal Revenue Code will continue to eliminate most capital gains taxes on sales that a public utility holding company makes of facilities in order to comply with SEC orders implementing the ’35 Act.
The 2005 Act promises to integrate and consolidate the transmission grids of North America and how they are operated. As noted, repeal of the ’35 Act will free utilities and other businesses to invest in geographically dispersed transmission systems. As a result, a relatively small number of companies specializing in transmission can be expected to acquire existing networks, while enhancing the connectivity between them.
The 2005 Act establishes a new electric reliability organization (ERO) into whose shoes the existing North American Electric Reliability Council (NERC) will likely step. Like NERC before it, ERO is charged with formulating standards for reliably operating U.S., Canadian and Mexican portions of the North American transmission networks. ERO will differ from NERC in that it will have enforcement teeth, which NERC never had. Working with regional subordinate councils (presumed to mirror, if not consolidate, the nine NERC regional councils), the ERO will develop and file with FERC reliability standards. Once blessed by FERC, the standards become binding on all users, owners and operators of the bulk power system, including municipal and cooperative utilities that ordinarily are exempt from federal regulatory authority. Both ERO and FERC can enforce the standards and penalize violators. Presidential agreements with Canada and Mexico will form the basis of international standards covering the entirety of the interconnected North American grids.
Perhaps most importantly, through a Byzantine exercise in federalism, the 2005 Act creates for the first time federal eminent domain for siting transmission rights-of-way, similar to (although more modest than) the federal siting authority that has long existed for interstate natural gas pipelines. New transmission sited under this authority will help integrate transmission operations and expand the size of accessible markets for wholesale power.
The 2005 Act also expands the scope of open and nondiscriminatory access to transmission and creates incentives to invest in transmission. The Act extends open access beyond investor-owned utilities to include the systems of municipally and cooperatively owned utilities, and charges FERC to develop within one year incentive rates for transmission services. The Act authorizes private investment in the federal transmission systems of the Western Area Power Administration and the Southwestern Power Administration, and permits those federal systems and each of the other federal power administrations, including giant Bonneville and the Tennessee Valley Authority, to surrender operational control over their transmission systems to regionally consolidated independent operators. And the tax provisions of Title XIII shorten from 20 to 15 years the depreciable lives of most high-voltage (69 kV or greater) transmission that is placed in service after April 11, 2005.
new generation hierarchy
The 2005 Act largely eliminates the policies of the Public Utility Regulatory Policies Act of 1978 (PURPA) that ultimately made natural gas-fired cogeneration the generation fuel and technology of choice in the 1990s and served as midwife for the renewable generation sector. Those policies are replaced with ones favoring coal and nuclear, and to a lesser extent promote hydroelectric expansion.
Federal energy policy has a long history of influencing the choice of resources and technologies used for power generation. The Bonneville Power Act in 1937 and concurrent federal investments in hydroelectric dams on the Columbia River wedded the Pacific Northwest to hydroelectric generation. Federal accident indemnity in the 1957 Atomic Energy Damages Act (Price-Anderson) made nuclear power financeable. The Fuel-Use Act of 1978 prevented the use of natural gas to generate electricity until advances in natural gas turbines and the Act’s repeal in 1992 ushered in the current era of natural gas dominance. The 2005 Act promises to introduce a new generation hierarchy.
Going forward, the 2005 Act largely repeals the so-called PURPA “put.” The “put” obligated traditional public utilities to sell backup power to, and buy for an attractive avoided-cost price the generation output of, qualifying facilities, i.e., cogenerators and producers using primarily renewable resources. Because traditional public utility ownership of qualifying facilities was limited to less than 50 percent, during the 1980s new entry and competition in wholesale power generation markets became the preeminent, although unintended, consequence of the PURPA “put.” The Energy Policy Act of 1992 later swelled the ranks of competitive generators by creating an additional class of PUHCA-exempt wholesale generators (EWGs). These cornerstones of wholesale power competition, qualifying facilities and EWGs, become obsolete in the 2005 Act. EWGs will have little purpose as there will be no ’35 Act from which to become exempt. New qualifying facilities will only be able to wield the “put” in limited circumstances where they are found to lack access to a competitive wholesale power market from which they can buy backup power and into which they can sell their output.
With open access to the transmission grid generally available in most markets, these circumstances will be the exception and not the rule. Moreover, even in the exceptional cases in which eligibility for the “put” continues to make qualifying facility status attractive, the definition of what is a “useful” thermal energy output for purposes of cogeneration is narrowed considerably by the 2005 Act to include only certain industrial or commercial applications.
At the same time as it eliminates advantages that competitive developers of predominantly natural gas-fired cogenerators and renewables enjoyed for a quarter century, the 2005 Act showers down both tax credits and generous funding on new or retrofitted coal, nuclear and, to a lesser extent, hydroelectric generation. The boons to nuclear in Title VI include $2 billion of federal “risk insurance” for as many as six new advanced plants, where risk is defined to include delay in achieving commercial operation; a production tax credit of 1.8 cents for the first 6,000 MW produced from certain advanced-design plants; a DOE grant of $1.25 billion for developing the next generation of nuclear plants and $2.7 billion in research and development; and an extension of Price-Anderson through 2025 on terms more favorable to the nuclear industry.
Support for coal in Title IV includes $1.8 billion in authorized funding for clean-coal projects; loan guarantees for greenhouse gas reducing technologies; three investment tax credits for up to 7,500 MW of new clean-coal capacity; and an accelerated seven-year depreciation of pollution control equipment installed after 1975 at coal-fired units. Other provisions promote coal leasing on federal lands. Hydroelectric generation, in turn, stands to benefit from more flexible licensing conditions and incentive payments for expanding the generating capacity of existing dams and conduits.
new police powers
Responding to the Western energy crisis of 2000-2001, the 2005 Act charges FERC with making wholesale power markets more transparent. It proscribes knowingly reporting false wholesale power prices or false data on transmission availability. It also makes it unlawful to violate FERC rules and regulations through manipulation or deception, and increases the scope and severity of penalties for doing so.
In coordination with the Commodity Futures Trading Commission’s (CFTC) enforcement of the Commodity Exchange Act, FERC is authorized to adopt rules to ensure transparency through the timely dissemination of information on the price and availability of electricity and transmission. Knowingly reporting false information on prices or transmission availability to FERC or any other federal agency with fraudulent intent to affect the collection of energy price or transmission availability data is prohibited and subject to civil penalties. In addition to fines, FERC is empowered to bar violators from future participation in the energy industry.
The 2005 Act looks to the antifraud provisions of the Securities Exchange Act of 1934 in adding new section 222 to the Federal Power Act, which makes it unlawful for any entity (including municipal and cooperative utilities) to employ any “manipulative or deceptive device or contrivance (as those terms are used in section 10(b) of the [Exchange] Act …) in contravention of such rules and regulations as [FERC] may prescribe … for the protection of electric ratepayers.” Section 10(b) of the Exchange Act prohibits the use of any manipulative or deceptive device or contrivance in connection with the purchase or sale of securities registered on a national exchange; case law spanning 70 years broadly defines what is manipulative or deceptive.
Time will tell how FERC will implement this new law. The text is not clear as to whether section 222 applies to pre-existing rules and regulations, such as FERC’s market behavior rules, which prohibit types of transactions, or is instead confined to prospective rules and regulations specifically adopted in connection with section 222. But given the breadth of what is deemed manipulative or deceptive under the Exchange Act, it can be safely assumed that FERC’s new authority to prosecute manipulation or deception will have a chilling effect on the types of wholesale energy and transmission transactions traders will be willing to develop and execute, at least in the near term. Unlike section 10(b) of the Exchange Act, which allows private rights of action against alleged violators of that section, the 2005 Act creates no private right of action, entrusting enforcement solely to FERC and federal prosecutors.
Administrative, civil and criminal penalties for violations of the Federal Power Act, including new section 222, are significantly increased and expanded. And FERC’s authority to order refunds of payments in wholesale energy and transmission transactions can now take effect immediately upon the filing of an administrative complaint. Refund liability is expanded as well to cover not only the sales of jurisdictional investor-owned public utilities, but also to cover the short-term sales of anyone who transacts in FERC-approved organized markets (e.g., the PJM Interconnection or California ISO) for short-term sales. Criminal penalties for violations of the Federal Power Act increase from $5,000 to $1 million and the maximum jail sentence jumps from two to five years. Criminal penalties for violations of FERC’s rules and regulations increase from $500 per day to $25,000 per day. Civil penalties increase from a maximum of $10,000 to $1 million for violations of any provision of the Federal Power Act.
Dan Watkiss is a partner with Bracewell & Giuliani in Washington, D.C. Focusing on litigation and arbitration, his clients include utilities, banks and other lenders and energy project developers. You can contact Dan at Dan.Watkiss@bracewellgiuliani.com.